Self-healing durable cement

ABSTRACT

According to at least one embodiment of the present description, a cement slurry includes 1% to 90% BWOC of a cement precursor material based on the total weight of the cement slurry; and from 1% to 40% BWOC of a swelling additive based on the total weight of the cement slurry. The swelling additive comprises at least one micronized rubber, at least one distillate, and at least one solvent-refined heavy paraffinic.

CROSS REFERENCE TO RELATED APPLICATION

This application is a divisional application of and claims priority to U.S. patent application Ser. No. 15/964,420 filed Apr. 27, 2018.

TECHNICAL FIELD

Embodiments of the present description generally relate to natural resource well drilling and, more specifically, to self-healing durable cements utilized in well drilling processes.

BACKGROUND

In well drilling processes, wellbores are commonly cemented, where the annulus between the casing and the wellbore wall is filled with cement, forming a cement sheath. High internal pressure may expand the casing and the cement sheath, which causes tensile stress on the cement sheath. Generally, cement materials are brittle, and the compressive strength is greater than the tensile strength of cement formations. Accordingly, the increased tensile stress on the cement sheath caused by the internal pressure may cause damage, such as cracking or fracture, to the cement sheath, which may lead to undesired leaking.

The damage to the cement sheath described in the preceding paragraph may be worsened by the high density of cement materials commonly used as cement sheaths in wellbores. Specifically, greater density cement materials are used in wellbores because they have less voids in the cement structures, which results in less migration of hydrocarbons from the geological formation into the well. However, the low number of voids in the cement material can increase the brittleness of the cement material, which may lead to damage of the cement structure when pressure is applied to the cement structure.

SUMMARY

Accordingly, there is a need for swelling additives that can be added to cement slurries to increase the tensile strength of the cement materials used in wellbores. Particularly, there is a need for swelling additives that migrate into cracks or fractures formed in a cement sheath during use, particularly after or during exposure of the cement to high internal pressure environments.

The present swelling additives address these needs by migrating into cracks or fractures formed in a cement sheath by swelling, or increasing in size or volume, upon exposure to hydrocarbons in either their gaseous or liquid form. Conventional cement additives are not able to provide the Young's modulus and Poisson's ratio achieved by the present swelling additives.

It has been discovered that swelling additives presently described may be used in cement materials having a broad range of densities. Therefore, the swelling additives presently described can be used in a large number of cement slurries without needing to be customized to each individual cement slurry. This allows the swelling additive to be used in more types of cement slurries, which allows for efficient production and decreased cost.

The presently described swelling additives generally include micronized rubber, distillates, and solvent-refined heavy paraffinics. The swelling additive may be added to the cement slurry in various amounts depending on the properties of the wellbore and the composition and properties of the cement material. For instance, a greater concentration of the swelling additive may be added to cement materials that have high density and a lesser concentration of the swelling additive may be added to cement materials that have a lesser density. The presently disclosed swelling additive may be added to the cement material as a dry ingredient to the dry cement mixture, or the swelling additive may be added to the cement slurry.

In one embodiment, a cement slurry comprises a cement precursor and a swelling additive that comprises at least one micronized rubber, at least one distillate, and at least one solvent-refined heavy paraffinic. For instance, in embodiments, a cement slurry comprises 1% to 90% by weight of the cement (BWOC) of a cement precursor material based on the total weight of the cement slurry, and from 1% to 40% BWOC of a swelling additive based on the total weight of the cement slurry. The swelling additive comprises at least one micronized rubber, at least one distillate, and at least one solvent-refined heavy paraffinic. It should be understood that, as used in this application, a percentage weight by BWOC is based upon the weight of the cement added to a mixture. For instance, a component present at 80% BWOC is present in a weight that is 80% of the weight of the cement.

In another embodiment, a cement slurry comprises at least one micronized rubber that comprises a mixture of carbon black, zinc oxide, and an elastomer. In particular, the carbon black comprises from 10.0% to 40.0% BWOC of the at least one micronized rubber, the zinc oxide comprises less than 3.0% BWOC of the at least one micronized rubber, and the elastomer comprises from 60.0% to 80.0% BWOC of the at least one micronized rubber. In yet another embodiment, a cement slurry comprises at least one micronized rubber that comprises a mixture of acrylonitrile rubber, zinc oxide, and styrene butadiene copolymer. In particular, the acrylonitrile rubber comprises from 25.0% to 50.0% BWOC of the at least one micronized rubber, the zinc oxide comprises less than 2.5% BWOC of the micronized rubber, and the styrene butadiene copolymer comprises from 50.0% to 70.0% BWOC of the micronized rubber.

In still another embodiment, a wellbore cementing system comprises a tubular positioned in a wellbore such that an annulus is formed between a geological formation and the tubular, and a cement structure in at least a portion of the annulus. The cement structure comprises from 1% to 40% BWOC of a swelling additive, and the swelling additive comprises at least one micronized rubber, at least one distillate, and at least one solvent-refined heavy paraffinic.

Additional features and advantages of the described embodiments will be set forth in the detailed description which follows, and in part will be readily apparent to those skilled in the art from that description or recognized by practicing the described embodiments, including the detailed description which follows as well as the claims.

DETAILED DESCRIPTION

In the present description, the following terms or units of measurement have been abbreviated, where:

° F.=degrees Fahrenheit;

cP=centipoise;

lb/gal=pounds per gallon;

OBM=oil-based mud;

g/cm³=grams per cubic centimeter;

BWOC=by weight of the cement;

gps=gallon per sack;

LVTD=linear variable differential transformer;

pcf=pounds per cubic foot;

psi=pounds per square inch;

rpm=rotations per minute; and

Embodiments of the present description are directed to swelling additives to be added to cement slurries, and methods of making and using swelling additives in cement slurries that result in a cement having, among other attributes, improved tensile strength as measured by the Young's modulus and Poisson's ratio of the cement. As used throughout the description, “swelling additive” refers to a mixture of components that are present in the cement slurry and, when the cement has hardened and becomes cracked, expands upon exposure to gaseous of liquid hydrocarbons and migrates into the cracks of the hardened cement. A “cement slurry” refers to a slurry which is cured to form a cement. In some embodiments, the swelling additive includes micronized rubber, distillates, and solvent-refined heavy paraffinic. According to one or more embodiments, a cement slurry comprises a cement precursor and a swelling additive that comprises at least one micronized rubber, at least one distillate, and at least one solvent-refined heavy paraffinic. For instance, in embodiments, a cement slurry comprises 1% to 90% BWOC of a cement precursor material based on the total weight of the cement slurry, and from 1% to 40% BWOC of a swelling additive based on the total weight of the cement slurry. The swelling additive comprises at least one micronized rubber, at least one distillate, and at least one solvent-refined heavy paraffinic. In still another embodiment, a wellbore cementing system comprises a tubular positioned in a wellbore such that an annulus is formed between a geological formation and the tubular, and a cement structure in at least a portion of the annulus. The cement structure comprises from 1% to 40% BWOC of a swelling additive, and the swelling additive comprises at least one micronized rubber, at least one distillate, and at least one solvent-refined heavy paraffinic.

A wellbore is a hole that extends from the surface to a location below the surface. The wellbore can permit access as a pathway between the surface and a hydrocarbon-bearing formation. The wellbore, defined and bound along its operative length by a wellbore wall, extends from a proximate end at the surface, through the subsurface, and into the hydrocarbon-bearing formation, where it terminates at a distal wellbore face. The wellbore forms a pathway capable of permitting both fluid and apparatus to traverse between the surface and the hydrocarbon-bearing formation.

Besides defining the void volume of the wellbore, the wellbore wall also acts as the interface through which fluid can transition between the interior of the wellbore and the formations through which the wellbore traverses. The wellbore wall can be unlined (that is, bare rock or formation) to permit such interaction with the formation or lined (that is, with casing, tubing, production liner or cement) so as to not permit such interactions.

The wellbore usually contains at least a portion of at least one tubular (that is, a fluid conduit) that links the interior of the wellbore to the surface. Examples of such fluid conduits or tubulars include casing, liners, pipes, tubes, coiled tubing and mechanical structures with interior voids. A fluid conduit connected to the surface is capable of permitting regulated fluid flow and access between equipment on the surface and the interior of the wellbore. Example equipment connected at the surface to the fluid conduit includes pipelines, tanks, pumps, compressors and flares. The fluid conduit is sometimes large enough to permit introduction and removal of mechanical devices, including tools, drill strings, sensors and instruments, into and out of the interior of the wellbore.

The fluid conduit made from a tubular usually has at least two openings (typically on opposing ends) with an enclosing surface having an interior and exterior surface. The interior surface acts to define the bounds of the fluid conduit. Examples of tubulars and portions of tubulars used in the wellbore as fluid conduits or for making or extending fluid conduits include casing, production liners, coiled tubing, pipe segments and pipe strings. An assembly of several smaller tubulars connected to one another, such as joined pipe segments or casing, can form a tubular that acts as a fluid conduit.

When positioning a tubular or a portion of tubular in the wellbore, the volume between the exterior surfaces of the fluid conduit or tubular portion and the wellbore wall of the wellbore forms and defines a wellbore annulus. The wellbore annulus has a volume in between the external surface of the tubular or fluid conduit and the wellbore wall.

The wellbore contains wellbore fluid from the first moment of formation until completion and production. The wellbore fluid serves several purposes, including well control (hydraulic pressure against the fluids in the hydrocarbon-bearing formation), wellbore wall integrity (hydraulic pressure on the wellbore wall; provides loss control additives) and lubricity (operating machinery). Wellbore fluid is in fluid contact with all portions of the wellbore and everything in the wellbore that is not fluidly isolated, including the tubular internal fluid conduit, the wellbore annulus, and the wellbore wall. Other fluid conduits coupled to the wellbore often contain at least some wellbore fluid.

While drilling, drilling fluid (“mud”) fills the interior of the wellbore as the wellbore fluid. Some muds are petroleum-based materials and some are water-based materials. Petroleum-based materials comprise at least 90 weight percent of an oil-based mud (OBM). Examples of suitable base petroleum materials include crude oils, distilled fractions of crude oil, including diesel oil, kerosene and mineral oil, and heavy petroleum refinery liquid residues. A minor part of the OBM is typically water or an aqueous solution that resides internally in the continuous petroleum phase. Other OBM components can include emulsifiers, wetting agents and other additives that give desirable physical properties.

While performing drilling operations, wellbore fluid circulates between the geological surface and the wellbore interior through fluid conduits. Wellbore fluid also circulates around the interior of the wellbore. The introduction of drilling fluid into the wellbore through a first fluid conduit at pressure induces the motivation for the fluid flow in the wellbore fluid. Displacing wellbore fluid through a second fluid conduit connected to the surface causes wellbore fluid circulation from the first fluid conduit to the second fluid conduit in the interior of the wellbore. The expected amount of wellbore fluid displaced and returned to the surface through the second fluid conduit is equivalent to the amount introduced into the wellbore through the first fluid conduit. Parts of the wellbore that are fluidly isolated do not support circulation.

The circulation and differences in movement of wellbore fluid within the wellbore can cause internal pressure of the wellbore to increase. This increase in internal pressure can place stresses on the components of the wellbore, such as, for example, the tubular. Therefore, a cement structure can be placed between the geological formation and the tubular.

Cementing is one of the most important operations in both drilling and completion of the wellbore. Primary cementing occurs at least once to secure a portion of the fluid conduit between the wellbore interior and the surface to the wellbore wall of the wellbore.

Primary cementing forms a protective solid sheath around the exterior surface of the introduced fluid conduit by positioning cement slurry in the wellbore annulus. Upon positioning the fluid conduit in a desirable location in the wellbore, introducing cement slurry into the wellbore fills at least a portion, if not all, of the wellbore annulus. When the cement slurry cures, the cement physically and chemically bonds with both the exterior surface of the fluid conduit and the wellbore wall, such as a geological formation, coupling the two. In addition, the solid cement provides a physical barrier that prohibits gases and liquids from migrating from one side of the solid cement to the other via the wellbore annulus. This fluid isolation does not permit fluid migration uphole of the solid cement through the wellbore annulus.

Displacing wellbore fluid for primary cementing operations is similar to establishing circulation in the wellbore fluid with a drilling mud. An amount of cement slurry introduced into the wellbore through a first fluid conduit induces fluid flow in the wellbore and displaces an equivalent amount of wellbore fluid to the surface through a second fluid conduit. In such an instance, the wellbore fluid includes a portion of the wellbore fluid previously contained in the wellbore before cement introduction as well as the amount of the introduced cement slurry.

As previously stated in this description, high density (such as cements with a density greater than 100 pounds per cubic foot (pcf)) cements are commonly used in wellbores, because the high density cements are less porous than low density cements (such as cements with a density less than 100 pcf) and, therefore, lessen the amount of undesirable components, such as undesirable hydrocarbons, that migrate from the geological formation into the tubular. However, internal pressure within the wellbore can cause tensile stress on the cement structure within the wellbore. Because the compressive strength of the cement is around ten times greater than the tensile strength of the cement, lesser tensile stresses placed on the cement component may be just as detrimental to the cement component as much greater compressive stresses. These tensile stresses can cause damage, such as cracks or fractures, to form in the cement structure. High density cements may be particularly prone to damage because the lessened porous structure of the high density cements, when compared to low density cements, may allow less flexibility to the cement structure. Once the cement structure is damaged, undesired component, such as undesired hydrocarbons, may migrate from the geological formation into the tubular.

This migration of components into the tubular can cause contamination of the wellbore product when the wellbore is in use, which required costly and time-consuming separations. Additionally, damage to the cement structure may allow components, such as undesired hydrocarbons to migrate into the tubular after the wellbore is abandoned. These components can then move through the tubular and exit the wellbore, which may be detrimental to the environment.

In view of these previously discussed issues that can occur when the cement structure in the wellbore is damaged, the presently described swelling additives may be added to the cement structure. Without being bound to any particular theory, it is believed that when the cement structure is damaged, such as by cracking or fracturing, the components, such as hydrocarbons, that migrate from the geological formation into the tubular contact the swelling additive causing the swelling additive to expand into the damage of the cement structure, thereby healing the damaged cement structure and preventing further migration of the undesired components from the geological structure into the tubular.

Without being bound by theory, it is believed that the swelling additives presently described may have a beneficial effect with respect to one or more of the problems with cement damage, as described. For instance, the swelling additive swells in the presence of hydrocarbons to fill cracks or other damage in the wellbore. As previously described in the present description, the swelling additive may comprise a micronized rubber, (which, as used in this description is defined as a rubber having particle sizes less than 500 microns) a distillate, and a solvent-refined heavy paraffinic. It should be understood that while embodiments of swelling additives presently described include these components, other components may be included in a swelling additive for various functional reasons, and it is contemplated that additional components may be included in the swelling additives presently described.

As presently described, swelling additives according to embodiments include a micronized rubber, a distillate, and a solvent-refined heavy paraffinic. Each of these components will be described.

According to one or more embodiments, the micronized rubber component of the swelling additive may be selected from the group consisting of nitrile rubber, styrene butadiene, fluoro silicone, isobutylene maleic anhydride, acrylic acid-type polymers, polyethylene oxide polymers, bentonite, and mixtures of these components. It should be understood that these micronized rubbers may, in embodiments, be used in any combination and in various amounts. It should also be understood that various mixtures of the presently described micronized rubbers may be added to the cement mixture depending on the conditions, such as temperature and pressure in the wellbore. Embodiments of the swelling additive presently described may include any combination of micronized rubber.

Some embodiments of the swelling additive comprise a mixture of carbon black, zinc oxide, and an elastomer as the micronized rubber component. The type of elastomer that is used in the swelling additive is not limited and, in various embodiments, any elastomer may be used. In such embodiments the carbon black may comprise from 10.0% to 40.0% BWOC of the micronized rubber component, such as from 15.0% to 35.0% BWOC of the micronized rubber component, or from 20.0% to 30.0% BWOC of the micronized rubber component. In such embodiments, the zinc oxide may comprise less than 3.0% BWOC of the micronized rubber component, such as less than 2.5% BWOC of the micronized rubber component, or less than 2.0% BWOC of the micronized rubber component. In such embodiments, the elastomer comprises from 60.0% to 80.0% BWOC of the micronized rubber component, such as from 65.0% to 75.0% BWOC of the micronized rubber component, or from 67.5% to 70.0% BWOC of micronized rubber component.

Other embodiments of the swelling additive comprise a mixture of acrylonitrile rubber, zinc oxide, and styrene butadiene copolymer as the micronized rubber component. In such embodiments the acrylonitrile rubber may comprise from 25.0% to 50.0% BWOC of the micronized rubber component, such as from 30.0% to 45.0% BWOC of the micronized rubber component, or from 35.0% to 40.0% BWOC of the micronized rubber component. In such embodiments, the zinc oxide may comprise less than 2.5% BWOC of the micronized rubber component, such as less than 2.0% BWOC of the micronized rubber component, or less than 2.0% BWOC of the micronized rubber component. In such embodiments, the styrene butadiene copolymer comprises from 50.0% to 70.0% BWOC of the micronized rubber component, such as from 53.0% to 68.0% BWOC of the micronized rubber component, or from 55.0% to 65.0% BWOC of the micronized rubber component.

The micronized rubber used in the swelling additive according to one or more embodiments, has a minimum operating temperature range from 80 degrees Fahrenheit (° F.) to 350° F., such as from 70° F. to 360° F., or from 60° F. to 370° F. It should be understood that minimum operating temperature range of the rubber is a minimal standard for the use of the micronized rubber. Accordingly, micronized rubbers having a greater or lesser operating temperature range than those specifically described may also be used in embodiments, so long as the micronized rubber has an operating temperature within the ranges presently described. For instance, a micronized rubber that has an operating temperature range from 50° F. to greater than 450° F. may be used in embodiments, but a micronized rubber that has an operating temperature range from 100° F. to 200° F. may not be suitable for use in all embodiments.

In addition, according to one or more embodiments, the micronized rubber may have a density from 10.0 pound per gallon (lb/gal) to 20.5 lb/gal, such as from 10.5 lb/gal to 20.0 lb/gal, from 11.0 lb/gal to 19.5 lb/gal, from 11.5 lb/gal to 19.0 lb/gal, from 12.0 lb/gal to 18.5 lb/gal, from 12.5 lb/gal to 18.0 lb/gal, from 13.0 lb/gal to 17.5 lb/gal, or from 13.5 lb/gal to 17.0 lb/gal. The specific gravity of the micronized rubber according to one or more embodiments may be from 0.85 to 1.10, from 0.90 to 1.00, or about 0.95. Although not being bound to any particular theory, the density and specific gravity of the micronized rubber presently described is believed to allow the micronized rubber to move freely and be well-dispersed in the swelling additive and in the cement slurry so that the micronized rubber may be uniformly present in the cement structure once it is cured. A well-dispersed swelling additive and micronized rubber component allows the micronized rubber to be present at or near any position in the cement structure in which damage may occur. Accordingly, the well-dispersed swelling additive and micronized rubber component may provide a self-healing cement that may heal itself, such as by having the swelling additive migrate into damaged areas of the cement structure, at nearly any position within the cement structure.

In addition to the density and specific gravity of the micronized rubber, the particle size of the micronized rubber may also aid in the dispersion of the micronized rubber and the swelling additive in the cement slurry. In addition, smaller particle-sized micronized rubber may be able to better fill cracks or fractures in the cement structure of the wellbore. For instance, smaller micronized rubber particles may be able to better fill smaller cracks or fracture in the cement structure, and smaller micronized rubber particles may be able to better fill intricate or complex shaped cracks or fractures in the cement structure of the wellbore. In one or more embodiments, at least 40% of the micronized rubber particles pass a 6.5 micron sieve test, such as at least 45% of the micronized rubber particles pass a 6.5 micron sieve test, at least 50% of the micronized rubber particles pass a 6.5 micron sieve test, at least 55% of the micronized rubber particles pass a 6.5 micron sieve test, at least 60% of the micronized rubber particles pass a 6.5 micron sieve test, or at least 65% of the micronized rubber particles pass a 6.5 micron sieve test.

It should be understood that the presently described properties of the micronized rubber component of the swelling additive may, in embodiments, not be uniformly present in the swelling additive. For instance, in embodiments where multiple micronized rubbers are added to the swelling additive, each micronized rubber may have its own density, specific gravity, and particle size. Accordingly, not every micronized rubber in the swelling additive will have the same properties. Although, in embodiments, each micronized rubber may have properties within the ranges presently described.

According to one or more embodiments, the presently described micronized rubber component of the swelling additive is mixed with a combination of a distillate and a solvent-refined heavy paraffinic.

In embodiments, the distillate may include one or more light distillate, medium distillate, and heavy distillate, which means effluents from the upper, middle, and lesser section of a distillation column, respectively. It should be understood that any number or combination of light distillates, medium distillates, or heavy distillates may be used in embodiments. These combinations of distillates, in embodiments, may include one or more light distillates, one or more medium distillates, and one or more heavy distillates. In other embodiments, one or more light distillates may be combined with one or more medium distillates. In alternative embodiments, one or more light distillates may be combined with one or more heavy distillates. In still other embodiments, one or more medium distillates may be combined with one or more heavy distillates. In yet another embodiment, the distillate may be one or more light distillates, or one or more medium distillates, or one or more heavy distillates. Light distillates, according to one or more embodiments, may include one or more of liquefied petroleum gas, gasoline, and naptha. In one or more embodiments, a light distillate is a light distillate fuel oil with a distillation temperature of 550° F. or less. In embodiments, medium distillates may include one or more of kerosene, jet fuel, and diesel fuel. Heavy distillates, according to embodiments, may include one or more fuel oil. It should be understood that each of the light, medium, and heavy distillates presently described may be used in any combination and number. Without being bound by any particular theory, it is believed that including a distillate may improve the properties of the final product such that they help in zonal isolation by forming a hydraulic barrier between a casing and the cement and the cement and the geological formation.

As presently defined, a “solvent-refined heavy paraffinic” is a combination of hydrocarbons obtained as the raffinate from a solvent extraction process and consists predominantly of C₂₀ to C₅₀ hydrocarbons having a viscosity of at least 20 centipoise (cP) at 100° F.

In one or more embodiments, the amount of the micronized rubber present in the swelling additive is from 50.0% to 95.0% BWOC, such as from 55.0% to 90.0% BWOC, from 60.0% to 85.0% BWOC, from 65.0% to 80.0% BWOC, or from 70.0% to 75.0% BWOC. The amount of distillates and solvent-refined heavy paraffinic in the swelling additive, according to one or more embodiments, is from 5.0% to 15.0% BWOC, such as from 7.5% to 12.5% BWOC, or from 9.0% to 11.0% BWOC. In other embodiments, the amount of distillates and solvent-refined heavy paraffinic in the swelling additive is from 5.0% to 10.0% BWOC, such as about 7.5% BWOC. The relatively great amount of micronized rubber in the swelling agent as compared to the amount of distillates and solvent-refined heavy paraffinic in the swelling additive allows the swelling additive to more readily migrate into damaged areas of the cement structure upon exposure to hydrocarbons migrating from the geological formation and into the tubular through damaged portions of the cement structure. In addition to the micronized rubber and the combination of distillates and solvent-refined heavy paraffinic, the swelling additive may include additional components that are subsequently described.

The swelling additive may additionally include one or more viscosifiers. The viscosifier induces rheological properties (that is, thickening) in the swelling additive composition that supports particle suspension and helps to prevent losses into the other fluids or the geological formation. The viscosifier can include biological polymers, clays, ethoxylated alcohols and polyether glycols. Biological polymers and their derivatives include polysaccharides, including xanthan gums, welan gums, guar gums, cellulose gums, corn, potato, wheat, maize, rice, cassava, and other food starches, succinoglycan, carrageenan, and scleroglucan and other intracellular, structural and extracellular polysaccharides. Biological polymers also include chemically modified derivatives such as carboxymethyl cellulose, polyanionic cellulose and hydroxyethyl cellulose (HEC) and forms of the polymers suspended in solvents. Clays and their derivatives include bentonite, sepiolite, attapulgite, and montmorillionite. Polyalklyene glycols include polyethylene glycols and polypropylene glycols, which are macromolecules with a series of internal ether linkages. Polyalklyene glycols are capable of dissolving in water and have a greater impact on viscosity with greater molecular weight.

The viscosifier can also include a viscosity thinner. A viscosity thinner reduces flow resistance and gel development by reducing viscosity of the swelling additive. Thinners comprising large molecular structures can also act as fluid loss additives. The functional groups of the viscosity thinners can act to emulsify oils and hydrocarbons present in the aqueous phase. Chemically modified viscosity thinners can attract solids and particles in the swelling additive and disperse such particles, the dispersion of particles preventing any increase in viscosity of the spacer fluid due to aggregation.

Polyphenolics, which include tannins, lignins, and humic acids, and chemically modified polyphenolics are useful viscosity thinners. Tannins and their chemically modified derivatives can either originate from plants or be synthetic. Examples of plant-originating tannins include tannins from pine, redwood, oak, quebracho trees and bark, grapes, blueberries, walnuts and chestnuts.

The swelling additive composition may also include one or more weighting agents. The weighting agent provides the swelling additive with the proper density profile. The proper weighing of the swelling additive composition relative to the cement slurry ensures that the swelling additive composition does not separate from the cement slurry. Weighting agents include sand, barite (barium sulfate), hematite, fly ash, silica sand, ilmenite, manganese oxide, manganese tetraoxide, zinc oxide, zirconium oxide, iron oxide and fly ash. According to one embodiment, the weighting agent for the swelling additive composition is barite.

The swelling additive composition may have a density in the range of from 0.5 grams per cubic centimeter (g/cm³) to 2.0 g/cm³, such as from 0.7 g/cm³ to 1.7 g/cm³, from 0.9 g/cm³ to 1.5 g/cm³, or from 1.0 g/cm³ to 1.2 g/cm³.

The swelling additive composition is formed by combining one or more of the micronized rubber, distillate, solvent-refined heavy paraffinic, the optional viscosifier, and the optional weighting agent. An exemplary method of combining the swelling additive components includes introducing into a vessel capable of retaining the swelling additive composition a sufficient quantity of each component into the vessel and mixing the blend such that all the swelling additive components are fully incorporated. Blending means can include mixing using a low- or high-shear blender.

A cement slurry may include water and a cement precursor, in addition to a presently described swelling additive. The cement slurry presently described may include silica sand with an average particle size from 80 to 120 microns, such as from 90 to 110 microns, or about 100 microns.

The cement slurry of the present description may include water, a cement precursor material, and the presently described swelling additive. The cement precursor material may be any suitable material which, when mixed with water, can be cured into a cement. The cement precursor material may be hydraulic or non-hydraulic. A hydraulic cement precursor material refers to a mixture of limestone, clay and gypsum burned together under extreme temperatures that may begin to harden instantly or within a few minutes while in contact with water. A non-hydraulic cement precursor material refers to a mixture of lime, gypsum, plasters and oxychloride. A non-hydraulic cement precursor may take longer to harden or may require drying conditions for proper strengthening, but often is more economically feasible. While hydraulic cement may be more commonly utilized in drilling applications, it should be understood that other cements are contemplated. In some embodiments, the cement precursor material may be Portland cement precursor. Portland cement precursor is a hydraulic cement precursor (cement precursor material that not only hardens by reacting with water but also forms a water-resistant product) produced by pulverizing clinkers, which contain hydraulic calcium silicates and one or more of the forms of calcium sulphate as an inter ground addition. Portland cement generally has a setting or thickening time in a range from 30 minutes to 15 hours. In embodiments, the desired setting time for such operations is 5 to 10 hours. In embodiments, the curing temperature is in a range from 70° F. to 500° F., such as from 200° F. to 300° F.

The cement precursor material may include one or more of calcium hydroxide, silicates, oxides, belite (Ca₂SiO₅), alite (Ca₃SiO₄), tricalcium aluminate (Ca₃Al₂O₆), tetracalcium aluminoferrite (Ca₄Al₂Fe₂O₁₀), brownmilleriate (4CaO.Al₂O₃. Fe₂O₃), gypsum (C aS O₄.2H₂O) sodium oxide, potassium oxide, limestone, lime (calcium oxide), hexavalent chromium, calcium alluminate, other similar compounds, and combinations of these. The cement precursor material may include Portland cement, siliceous fly ash, calcareous fly ash, slag cement, silica fume, any known cement precursor material or combinations of any of these. In one or more embodiments, the cement precursor comprises silica sand. In some embodiments, the cement slurry may contain from 1% BWOC to 90% BWOC of the cement precursor material based on the total weight of the cement slurry. For instance, the cement slurry may contain from 1% BWOC to 80% BWOC, from 10% BWOC to 70% BWOC, or from 20% BWOC to 60% BWOC. The cement slurry may contain from 55% BWOC to 90% BWOC, from 60% BWOC to 90% BWOC, from 70% BWOC to 90% BWOC, or from 75% BWOC to 90% BWOC of the cement precursor material.

Accordingly, in embodiments, the cement slurry may contain from 1% to 40% BWOC of the swelling additive based on the total weight of the cement slurry. For instance, the cement slurry may contain from 5% to 40% BWOC, from 10% to 30% BWOC, or from 10% to 20% BWOC. The cement slurry may contain from 15% to 40% BWOC, from 20% to 40% BWOC, from 30% to 40% BWOC, or from 35% to 40% BWOC of the swelling additive.

Water may be added to the cement precursor material to produce the slurry. The water may be distilled water, deionized water, tap water, brackish water, formation water, produced water, raw seawater, or filtered seawater. In some embodiments, the water may contain additives or contaminants. For instance, the water may include freshwater or seawater, natural or synthetic brine, or salt water. In some embodiments, salt or other organic compounds may be incorporated into the water to control certain properties of the water, and thus the cement slurry, such as density. Without being bound by any particular theory, increasing the saturation of water by increasing the salt concentration or the level of other organic compounds in the water may increase the density of the water, and thus, the cement slurry. Suitable salts may include, but are not limited to, alkali metal chlorides, hydroxides, or carboxylates. In some embodiments, suitable salts may include sodium, calcium, cesium, zinc, aluminum, magnesium, potassium, strontium, silicon, lithium, chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, sulfates, phosphates, oxides, fluorides, and combinations of these.

In some embodiments, the cement slurry may contain from 5% to 70% BWOC water based on the total weight of the cement slurry. In some embodiments, the cement slurry may contain from 5% to 50% BWOC, from about 5% to 30% BWOC, 5% to 20% BWOC, from 5% to 10% BWOC, or from 10% to 70% BWOC, from 30% to 70% BWOC, or from 50% to 70% BWOC of water. The cement slurry may contain from 20% to 40% BWOC, or from 25% to 35% BWOC, such as 30% BWOC of water based on the total weight of the cement slurry.

The cement slurry presently described may also include an expansion additive. As the cement dehydrates, the volume of the cement decreases, which can cause separation between the cement and the casing or the cement and the geological formation. Expansion additives improve the bonding of the cement to the casing or the geological formation by increasing the volume of the cement so that a lesser amount of shrinkage occurs upon dehydration. The expansion additive is used to achieve good bonding with the geological formation of the wellbore. At wellbore temperatures of 140° F. or greater, MgO, CaO, and mixtures thereof may be used as the expansion additive in the cement slurry. However, at temperatures lesser than 140° F., MgO and CaO do not expand quickly enough to provide adequate binding to the geological formation. Accordingly, at wellbore temperatures less than 140° F., crystalline SiO₂ may be used as the expansion additive because it expands more quickly than MgO. In one or more embodiments, D174 manufactured by Schlumberger may be used as a low-temperature expansion additive (such as, at temperatures less than 230° F.), Halliburton Micro bond L may also be used as a low temperature expansion additive (such as, at temperatures less than 230° F.), Halliburton Micro bond HT may be used as a high temperature expansion additive (such as, at temperatures greater than 230° F.), and Schlumberger D 176 can be used as a high temperature expansion additive (such as, at temperatures greater than 230° F.).

In some embodiments, the cement slurry may contain from 0.1% to 50% BWOC of the one or more additional additives, as subsequently described, based on the total weight of the cement slurry. For instance, the cement slurry may contain from 0.1% to 8% BWOC of the one or more additional additives, from 0.1% to 5% BWOC of the one or more additives, or from 0.1% to 3% BWOC of the one or more additives. The cement slurry may contain from 1% to 10% BWOC of the one or more additives, from 1% to 8% BWOC, from 1% to 5% BWOC, or from 1% to 3% BWOC of the one or more additives. In some embodiments, the cement slurry may contain from 3% to 5% BWOC, from 3% to 8% BWOC, from 3% to 10% BWOC, or from 5% to 10% BWOC of the one or more additives.

In some embodiments, the one or more additional additives may include a dispersant containing one or more anionic groups. For instance, the dispersant may include synthetic sulfonated polymers, lignosulfonates with carboxylate groups, organic acids, hydroxylated sugars, other anionic groups, or combinations of any of these. Without being bound by any particular theory, in some embodiments, the anionic groups on the dispersant may be adsorbed on the surface of the cement particles to impart a negative charge to the cement slurry. The electrostatic repulsion of the negatively charged cement particles may allow the cement slurry to be dispersed and more fluid-like, improving flowability. This may allow for one or more of the following: reduced turbulence at lesser pump rates; reduction of friction pressure when pumping; reduction of water content; and improvement of the performance of fluid loss additives.

In some embodiments, the one or more additional additives may alternatively or additionally include a fluid loss additive. In some embodiments, the cement fluid loss additive may include non-ionic cellulose derivatives. In some embodiments, the cement fluid loss additive may be hydroxyethylcellulose (HEC). In other embodiments, the fluid loss additive may be a non-ionic synthetic polymer (for example, polyvinyl alcohol or polyethyleneimine). In some embodiments, the fluid loss additive may be an anionic synthetic polymer, such as 2-acrylamido-2-methylpropane sulfonic acid (AMPS) or AMPS-copolymers, including lattices of AMPS-copolymers. In some embodiments, the fluid loss additive may include bentonite, which may additionally viscosify the cement slurry and may, in some embodiments, cause retardation effects. Without being bound by any particular theory, the surfactant may reduce the surface tension of the aqueous phase of the cement slurry, thus reducing the fluid lost by the slurry. Additionally, the carboxylic acid may further reduce the fluid loss of the cement slurry by plugging the pores of the cement filter cake, minimizing space for the water or other fluids to escape from the cement.

In some embodiments, the fluid loss additive may contain a carboxylic fatty acid having from 16 to 18 carbon atoms, which may be used in combination with the surfactant to reduce fluid loss in the cement slurry. The carboxylic fatty acid includes any acids having formula ROOH in which R is a saturated or unsaturated, linear, or branched hydrocarbyl group having from 16 to 18 carbons, such as a hydrocarbyl group having 16 carbons, 17 carbons, or 18 carbons. Examples of suitable carboxylic fatty acids include palmitic acid, palmitoleic acid, vaccenic acid, oleic acid, elaidic acid, linoleic acid, α-linolenic acid, γ-linolenic acid, stearidonic acid, and combinations thereof. The surfactant may be in accordance with any of the embodiments previously described. In some specific embodiments, the fluid loss additive may contain a combination of an ethylene oxide condensate of branched isotridecyl alcohol with a fatty acid having from 16 to 18 carbon atoms in the hydrocarbyl group.

Following introduction of the cement slurry into the wellbore, the cement slurry may form cement through curing. As used throughout the description, “curing” refers to providing adequate moisture, temperature and time to allow the concrete to achieve the desired properties (such as hardness) for its intended use through one or more reactions between the water and the cement precursor material. Curing may be a passive step where no physical action is needed (such as cement that cures in ambient conditions when untouched) In contrast, “drying” refers to merely allowing the concrete to achieve a moisture condition appropriate for its intended use, which may only involve physical state changes, as opposed to chemical reactions. In some embodiments, curing the cement slurry may refer to passively allowing time to pass under suitable conditions upon which the cement slurry may harden or cure through allowing one or more reactions between the water and the cement precursor material. Suitable conditions may be any time, temperature, pressure, humidity, and other appropriate conditions known in the cement industry to cure a cement composition. In some embodiments, suitable curing conditions may be ambient conditions. Curing may also involve actively hardening or curing the cement slurry by, for instance, introducing a curing agent to the cement slurry, providing heat or air to the cement slurry, manipulating the environmental conditions of the cement slurry to facilitate reactions between the water and the cement precursor, a combination of these, or other such means.

In some embodiments, curing may occur at a relative humidity of greater than or equal to 80% in the cement slurry and a temperature of greater than or equal to 50° F. for a time period of from 1 to 14 days. Curing may occur at a relative humidity of from 80% to 100%, such as from 85% to 100%, or 90% to 100%, or from 95% to 100% relative humidity in the cement slurry. The cement slurry may be cured at temperatures of greater than or equal to 50° F., such as greater than or equal to 75° F., greater than or equal to 80° F., greater than or equal to 100° F., or greater than or equal to 120° F. The cement slurry may be cured at temperatures of from 50° F. to 250° F., or from 50° F. to 200° F., or from 50° F. to 150° F., or from 50° F. to 120° F. The cement slurry may be cured for from 1 day to 14 days, such as from 3 to 14 days, or from 5 to 14 days, or from 7 to 14 days, or from 1 to 3 days, or from 3 to 7 days.

Once the cement slurry is cured, the cured cement constitutes a cement structure within the wellbore. The cement structure will have various properties that indicate the physical strength of the cement structure. For instance, Young's modulus measures the ratio of the stress (force per unit area) along an axis to the strain (ratio of deformation over initial length) along that axis. Thus, Young's modulus can be used to show the elasticity or stiffness of the cement structure within the wellbore and gives insight into the tensile strength of the cement structure. Poisson's ratio is a measure of transverse strain to axial strain, and measures the deformation capacity of the cement structure. The greater the deformation capacity (that is, the greater Poisson's ratio) the less likely the cement structure will be damaged as temperature and pressure changes within the wellbore. In one or more embodiments, the Young's modulus and the Poisson's ratio of the cement structure was measured 10 days after curing, 20 days after curing, and 30 days after curing.

In one or more embodiments, the Young's modulus of the cement structure 10 days after curing is from 7.50×10⁵ pounds per square inch (psi) to 7.95×10⁵ psi, such as from 7.60×10⁵ psi to 7.95×10⁵ psi, from 7.70×10⁵ psi to 7.95×10⁵ psi, from 7.75×10⁵ psi to 7.95×10⁵ psi, from 7.80×10⁵ psi to 7.95×10⁵ psi, or from 7.90×10⁵ psi to 7.95×10⁵ psi. In other embodiments, the Young's modulus of the cement structure 10 days after curing is from 7.50×10⁵ psi to 7.90×10⁵ psi, such as from 7.50×10⁵ psi to 7.80×10⁵ psi, from 7.50×10⁵ psi to 7.70×10⁵ psi, from 7.50×10⁵ psi to 7.60×10⁵ psi, or from 7.50×10⁵ psi to 7.55×10⁵ psi. In one or more embodiments, the Young's modulus of the cement structure 20 days after curing is from 5.50×10⁵ psi to 6.00×10⁵ psi, such as from 5.60×10⁵ psi to 6.00×10⁵ psi, from 5.70×10⁵ psi to 6.00×10⁵ psi, from 5.75×10⁵ psi to 6.00×10⁵ psi, from 5.80×10⁵ psi to 6.00×10⁵ psi, or from 5.90×10⁵ psi to 6.00×10⁵ psi. In other embodiments, the Young's modulus of the cement structure 20 days after curing is from 5.50×10⁵ psi to 5.95×10⁵ psi, such as from 5.50×10⁵ psi to 5.90×10⁵ psi, from 5.50×10⁵ psi to 5.80×10⁵ psi, from 5.50×10⁵ psi to 5.70×10⁵ psi, or from 5.50×10⁵ psi to 5.60×10⁵ psi. In one or more embodiments, the Young's modulus of the cement structure 30 days after curing is from 7.00×10⁵ psi to 7.50×10⁵ psi, such as from 7.10×10⁵ psi to 7.50×10⁵ psi, from 7.20×10⁵ psi to 7.50×10⁵ psi, from 7.25×10⁵ psi to 7.50×10⁵ psi, from 7.30×10⁵ psi to 7.50×10⁵ psi, or from 7.40×10⁵ psi to 7.50×10⁵ psi. In other embodiments, the Young's modulus of the cement structure 30 days after curing is from 7.00×10⁵ psi to 7.45×10⁵ psi, such as from 7.00×10⁵ psi to 7.40×10⁵ psi, from 7.00×10⁵ psi to 7.30×10⁵ psi, from 7.00×10⁵ psi to 7.20×10⁵ psi, or from 7.00×10⁵ psi to 7.10×10⁵ psi.

In one or more embodiments, the Poisson's ratio of the cement structure 10 days after curing is from 0.370 psi to 0.400 psi, such as from 0.375 psi to 0.400 psi, from 0.380 psi to 0.400 psi, from 0.385 psi to 0.400 psi, from 0.390 psi to 0.400 psi, or from 0.395 psi to 0.400 psi. In other embodiments, the Poisson's ratio of the cement structure 10 days after curing is from 0.370 psi to 0.395 psi, from 0.370 psi to 0.390 psi, from 0.370 psi to 0.385 psi, from 0.370 psi to 0.380 psi, or from 0.370 psi to 0.375 psi. In one or more embodiments, the Poisson's ratio of the cement structure 20 days after curing is from 0.330 psi to 0.360 psi, such as from 0.335 psi to 0.360 psi, from 0.340 psi to 0.360 psi, from 0.345 psi to 0.360 psi, from 0.350 psi to 0.360 psi, or from 0.355 psi to 0.360 psi. In other embodiments, the Poisson's ratio of the cement structure 20 days after curing is from 0.330 psi to 0.355 psi, from 0.330 psi to 0.350 psi, from 0.330 psi to 0.345 psi, from 0.330 psi to 0.340 psi, or from 0.330 psi to 0.335 psi. In one or more embodiments, the Poisson's ratio of the cement structure 30 days after curing is from 0.705 psi to 0.735 psi, such as from 0.710 psi to 0.735 psi, from 0.715 psi to 0.735 psi, from 0.720 psi to 0.735 psi, from 0.725 psi to 0.735 psi, or from 0.730 psi to 0.735 psi. In other embodiments, the Poisson's ratio of the cement structure 30 days after curing is from 0.705 psi to 0.730 psi, from 0.705 psi to 0.725 psi, from 0.705 psi to 0.720 psi, from 0.705 psi to 0.715 psi, or from 0.705 psi to 0.710 psi.

The cement structure may, in embodiments, have a density from 100 pounds per cubic foot (pcf) to 170 pcf, such as from 105 pcf to 165 pcf, from 110 pcf to 160 pcf, from 115 pcf to 155 pcf, from 120 pcf to 150 pcf, from 125 pcf to 145 pcf, or from 130 pcf to 140 pcf. If the density of the cement structure is less than 100 pcf, the cement structure may include pores that allow undesirable components, such as undesirable hydrocarbons, to migrate from the geological formation into the tubular through the cement structure. However, if the density of the cement structure exceeds 170 pcf, the cement structure may not have enough elasticity to survive exposure to tensile stresses caused by internal pressures in the wellbore. As presently described, swelling additives according to embodiments may be used in a wide array of cements have many densities.

According to a first aspect, a cement slurry comprises: 1% to 90% BWOC of a cement precursor material based on a total weight of the cement slurry; and from 1% to 40% BWOC of a swelling additive based on the total weight of the cement slurry, where the swelling additive comprises at least one micronized rubber, at least one distillate, and at least one solvent-refined heavy paraffinic.

A second aspect comprises the cement slurry of the first aspect, where the swelling additive comprises the at least one micronized rubber in an amount from 50.0% to 95.0% BWOC, and comprises a combination of the at least one distillate and at least one solvent-refined heavy paraffinic in an amount from 5.0% to 15.0% BWOC.

A third aspect comprises the cement slurry of any one of the first and second aspects, where the at least one micronized rubber comprises nitrile rubber, styrene butadiene, fluoro silicone, isobutylene maleic anhydride, acrylic acid-type polymers, polyethylene oxide polymers, bentonite, and mixtures of these components.

A fourth aspect comprises the cement slurry of any one of the first to third aspects, where the at least one micronized rubber has a density from 10.0 lb/gal to 20.5 lb/gal.

A fifth aspect comprises the cement slurry of any one of the first to fourth aspects, where the at least one micronized rubber has a specific gravity from 0.85 to 1.10.

A sixth aspect comprises the cement slurry of any one of the first to fifth aspects, where the at least one micronized rubber comprises a mixture of carbon black, zinc oxide, and an elastomer.

A seventh aspect comprises the cement slurry of the sixth aspect, where the carbon black comprises from 10.0% to 40.0% BWOC of the at least one micronized rubber, the zinc oxide comprises less than 3.0% BWOC of the at least one micronized rubber, and the elastomer comprises from 60.0% to 80.0% BWOC of the at least one micronized rubber.

An eighth aspect comprises the cement slurry of any one of the first to fifth aspects, where the at least one micronized rubber comprises a mixture of acrylonitrile rubber, zinc oxide, and styrene butadiene copolymer.

A ninth aspect comprises the cement slurry of the eighth aspect, where the acrylonitrile rubber comprises from 25.0% to 50.0% BWOC of the at least one micronized rubber, the zinc oxide comprises less than 2.5% BWOC of the micronized rubber, and the styrene butadiene copolymer comprises from 50.0% to 70.0% BWOC of the micronized rubber.

A tenth aspect comprises the cement slurry of any one of the first to ninth aspects, where the swelling additive has a density from 0.5 g/cm³ to 2.0 g/cm³.

According to an eleventh aspect, a wellbore cementing system comprises: a tubular positioned in a wellbore such that an annulus is formed between a geological formation and the tubular; and a cement structure positioned in at least a portion of the annulus, where the cement structure comprises from 1% to 40% BWOC of a swelling additive, and where the swelling additive comprises at least one micronized rubber, at least one distillate, and at least one solvent-refined heavy paraffinic.

A twelfth aspect comprises the wellbore cementing system of the eleventh aspect, where the at least one micronized rubber comprises nitrile rubber, styrene butadiene, fluoro silicone, isobutylene maleic anhydride, acrylic acid-type polymers, polyethylene oxide polymers, bentonite, and mixtures of these components.

A thirteenth aspect comprises the wellbore cementing system of any one of the eleventh and twelfth aspects, where the at least one micronized rubber has a density from 10.0 lb/gal to 20.5 lb/gal.

A fourteenth aspect comprises the wellbore cementing system of any one of the eleventh to thirteenth aspects, where the at least one micronized rubber has a specific gravity from 0.85 to 1.10.

A fifteenth aspect comprises the wellbore cementing system of any one of the eleventh to fourteenth aspects, where the at least one micronized rubber comprises a mixture of carbon black, zinc oxide, and an elastomer.

A sixteenth aspect comprises the wellbore cementing system of the fifteenth aspect, where the carbon black comprises from 10.0% to 40.0% BWOC of the at least one micronized rubber, the zinc oxide comprises less than 3.0% BWOC of the at least one micronized rubber, and the elastomer comprises from 60.0% to 80.0% BWOC of the at least one micronized rubber.

A seventeenth aspect comprises the wellbore cementing system of any one of the eleventh to fourteenth aspects, where the at least one micronized rubber comprises a mixture of acrylonitrile rubber, zinc oxide, and styrene butadiene copolymer.

An eighteenth aspect comprises the wellbore cementing system of the seventeenth aspect, where the acrylonitrile rubber comprises from 25.0% to 50.0% BWOC of the at least one micronized rubber, the zinc oxide comprises less than 2.5% BWOC of the micronized rubber, and the styrene butadiene copolymer comprises from 50.0% to 70.0% BWOC of the micronized rubber.

A nineteenth aspect comprises the wellbore cementing system of any one of the eleventh to eighteenth aspects, where the swelling additive has a density from 0.5 g/cm³ to 2.0 g/cm³.

A twentieth aspect comprises the wellbore cementing system of any one of the eleventh to nineteenth aspects, where the cement structure has a Young's modulus 10 days after curing from 7.50×10⁵ psi to 7.95×10⁵ psi.

A twenty first aspect comprises the wellbore cementing system of any one of the eleventh to twentieth aspects, where the cement structure has a Young's modulus 20 days after curing from 5.50×10⁵ psi to 6.00×10⁵ psi.

A twenty second aspect comprises the wellbore cementing system of any one of the eleventh to twenty first aspects, where the cement structure has a Young's modulus 30 days after curing from 7.00×10⁵ psi to 7.50×10⁵ psi.

A twenty third aspect comprises the wellbore cementing system of any one of the eleventh to twenty second aspects, where the cement structure has a Poisson's ratio 10 days after curing from 0.370 psi to 0.400 psi.

A twenty fourth aspect comprises the wellbore cementing system of any one of the eleventh to twenty third aspects, where the cement structure has a Poisson's ratio 20 days after curing from 0.330 psi to 0.360 psi.

A twenty fifth aspect comprises the wellbore cementing system of any one of the eleventh to twenty fourth aspects, where the cement structure has a Poisson's ratio 30 days after curing from 0.705 psi to 0.735 psi.

A twenty sixth aspect comprises the wellbore cementing system of any one of the eleventh to twenty fifth aspects, where the cement structure has a density from 100 pcf to 170 pcf.

Examples

The following examples illustrate one or more features of the present description. It should be understood that these examples are not intended to limit the scope of the description or the appended claims in any manner.

A cement slurry was tested for rheology, thickening time, fluid loss, free water, sedimentation, expansion performance, and mechanical properties in order to evaluate the performance of cement slurry. The cement slurry included silica sand with an average particle size of 100 microns. Two sizes of silica were used, such as Schlumberger micro fine silica (D178) and Schlumberger coarse silica (D030), a expansion additive, and (swelling) additive composed of micronized rubber powder prepared from distillates (petroleum) and solvent-refined heavy paraffinic. The swelling additive was a black non-mineral coarse particle and its nominal (absolute) density is 1.2 g/cm³.

The cement slurry formulation was prepared in the lab using a standard A American Petroleum Institute (API) blender. The maximum speed used during slurry preparation was 12,000 rotations per minute (rpm). The slurry was mixed in the blender for 15 seconds at 4,000 rpm and 35 seconds at 12,000 rpm. The slurry was then conditioned in the atmospheric consistometer before obtaining the rheological measurements. A Fann viscometer (Model-35) was utilized to measure the slurry apparent viscosity.

The prepared slurry was then poured into API standard High Pressure/High Temperature (HP/HT) consistometer slurry cup for a thickening time test, which is important to evaluate the pumpability of the cement slurry.

As in API Recommended testing 10-B2 a free water test was used to measure water separation by using 250 ml graduated cylinder in the cement slurry for 2 hours. Settling was measured by comparing densities of different sections of the cement column cured. The cylindrical shaped cell, used to cure the cement formula for settling test, had a diameter of 1.4″ and length of 12″. Sections of 2″ long were taken from different parts of the cement column sample. The cement slurry was cured at 8000 psi and 300° F. for at least 3 days.

To measure expansion, an annular expansion ring test was used to measure linear expansion under condition of free access to water. Free access to water means an open system. An annular expansion mold was used to simulate the annulus of the well. The cement slurry was poured into the annular space in the mold and then the mold was placed into water bath or a pressurized curing chamber. Water was in contact with the slurry during the entire curing process. The diameter increased if the cement expanded. API Recommended testing 10-B2

A composition of the slurry is provided in Table 1, and properties of the cement slurry are provided in Tables 2 and 3. In Table 2, the rheology of the cement slurry was measured using a standard viscometer. Ramp up in Table 2 indicates increasing rpm to 3, 6, 100, 200, and 300. Ramp down in Table 2 indicates decreasing rpm from 300 to 200, 100, 6, and 3. In Table 3 the thickening time of the slurry is measured by pouring the slurry into a cylinder with 0 degree inclination (a vertical cylinder) and heating to 80° F. for several hours. The solid sedimentation at the bottom section of the cylinder is observed. No sedimentation means that cement will have good quality at both the top and the bottom of the cement structure. The API fluid loss is a test that measures the volume of filtrate of the cement slurry at high temperature and pressure. In Table 3, the “BC” is the Bearden unit of consistency, and an acceptable fluid level is 0 ml/250 ml at atmospheric conditions. The components used in Table 1 are all manufactured by Schlumberger, and the Schlumberger material number is listed in Table 1.

TABLE 1 Cement Slurry (106 pcf): Component Concentration Unit of Measure Fresh Water 6.011 gps Flexible Agent (D258) 20.8 % BWOC Silica (D178) 35.8 % BWOC Weighting Agent (D076) 17.6 % BWOC Swelling Agent (XE203) 2.0 % BWOC Expansion Agent (D174) 2.6 % BWOC Weighting Agent ((D157) 17.1 % BWOC Antifoam (D047) 0.004 gps Dispersant (D065) 0.450 % BWOC GASBLOK LT (D500) 1.473 gps Retarder (D081) 0.042 gps

TABLE 2 Rheology of the Cement Slurry (106 pcf): Rheology: T = 80 F. Ramp Up Ramp Down Average 300 122 122 122 200 97 95 96 100 65 63 64 60 49 46 48 30 35 33 34 6 19 19 19 3 14 16 15

TABLE 3 Properties of Cement Slurry Consistency Time Thickening time 100 Bc 12:23 hrs Free Fluid 0 ml/250 ml in 2 hrs 80 F., 0 deg inclination No sedimentation Fluid loss API fluid loss 22 ml 30 min, 265 F., and 1000 psi

Single stage triaxial tests were performed on 13 dry cement core plugs with lengths ranging between 2.997 and 3.020 inches and having a diameter between 1.490 and 1.510 inches to measure static and dynamic properties through ultrasonic and shear velocities. These properties were determined at a confining pressures of 1 MPa (1 MPa=145.038 psi) and included the Young's modulus, the Poisson's Ratio, the Peak Strength.

During each test performed, a series of ultrasonic measurements and dynamic moduli were computed. The final dynamic moduli of a plug were taken as the average of the moduli computed at each ultrasonic velocity measurement.

Sample Preparation included the following steps: (1) cement core plug formulation was selected and drilled; (2) surfaces of the parallel end faces were grinded until they became flat to within 0.001 inches; and (3) the plug was jacketed and positioned so that two end caps equipped with velocity transducers could be placed on the ends of the sample while a coupling medium was set between the plug flat surfaces and the transducer.

After completing the sample preparation as per the procedure in the preceding paragraph, the plug was equipped and loaded onto the testing frame as follows: (a) the jacket was clamped to the transducers from both ends to allow for the hydrostatic confining pressure around the sample to be applied; (b) radial and axial limited variable differential transformers (LVTD) were positioned around and along the sample to measure radial and axial displacements respectively; and (c) confining pressure was applied hydrostatically around the sample. The confining pressures were selected to simulate the stress condition in the vicinity of the wellbore.

For this example single stage triaxial tests at low confining pressures were conducted. The dynamic elastic properties were determined simultaneously with the static properties using ultrasonic measurements. The static properties are required for many petroleum engineering applications; however, dynamic data are often collected in the field and therefore the necessary calibration must be obtained to design specific treatments related to wellbore stability, hydraulic fracturing, and sand control.

To perform dynamic measurements (ultrasonic velocity measurements), the end caps of the core sample were equipped with ultrasonic transducers and receivers which can generate and detect, respectively, both compressional and shear waves. One transducer was a transmitter which was excited to induce an ultrasonic wave at a frequency of 700 kilohertz (kHz) and the other one was a receiver. In this example the velocities of these waves were used to compute the dynamic Young's modulus and Poisson's ratio.

Mechanical Properties Simulation

Young's modulus E characterizes the material's longitudinal deformation under uniaxial loading, such as along an axis when opposing forces are applied along that axis. Transverse deformation is quantified with the Poisson's ratio υ, which is the ratio between transverse and axial deformation. A Poisson's ratio equal to 0.5 means the material is incompressible. Conventional cements have a Poisson's ratio of approximately 0.15.

Results of the mechanical properties are shown in Table 4 and Table 5

TABLE 4 Cement slurry (105 pcf) mechanical test results from ASTM D2850 and D4767 Standard Test Methods Young Peak Duration, Modulus Poisson Ratio Strength, Sample Type days (static), psi (static), psi psi Comp. Ex. 1 10 2.748 × 10⁶ 0.378 7,733.9 Comp. Ex. 2 20 2.453 × 10⁶ 0.323 7,468.1 Comp. Ex. 3 30 1.787 × 10⁶ 0.081 11,077.2 Ex. 1 10 7.758 × 10⁵ 0.389 2,841.3 Ex. 2 20 5.939 × 10⁵ 0.347 3,207.1 Ex. 3 30 7.224 × 10⁵ 0.208 3,545.6

TABLE 5 Cement slurry (118 pcf) mechanical test results: Sat. Static Dynamic bulk Confining Young's Young's Static Dynamic density pressure modulus modulus Poisson's Poisson's Peak Sample (g/cc) (psi) (psi) (psi) ratio ratio strength Remarks Comp. Ex. 1 1.91 183.18 1.06 × 10⁶ 0.261 2998 10 day Comp. Ex. 2 1.90 188.08 6.17 × 10⁵ 1.53 × 10⁶ 0.389 0.316 3160 20 days Comp. Ex. 3 1.89 188.08 4.49 × 10⁵ 1.42 × 10⁶ 0.521 0.334 3033 30 days Ex. 1 1.98 183.18 9.41 × 10⁵ 2.63 × 10⁶ 0.111 0.290 4730 10 days conventional cement Ex. 2 1.97 183.18 1.31 × 10⁶ 2.6 × 10⁶ 0.237 0.295 5282 20 days conventional cement Ex. 3 1.98 183.18 1.65 × 10⁶ 2.66 × 10⁶ 0.260 0.293 7214 30 days conventional cement

Linear Expansion Test

A hardened cement sample was placed in a container with a hydrocarbon fluid from an oil-producing well. The fluid was heated to 150° F. and the procedure from API Recommended Practice 10B-5 was followed. The results are shown in Table 6.

TABLE 6 Cell A Measurement Cell A Linear Expansion Temperature Day (mm) (%) (° F.) 0 16.70 0.000 Room Temp. 1 16.90 0.072 Room Temp. 2 16.95 0.090 Room Temp. 3 16.95 0.090 Room Temp. 6 16.95 0.090 Room Temp. 7 17.45 0.269 150° F.

The sample, after exposure to the hydrocarbons, showed expansion from 16.95 mm to 17.45 mm and liner expansion from 0.090% to 0.269%, as shown in the data in Table 6 from day 6 to day 7.

Having described the subject matter of the present description in detail and by reference to specific embodiments, it is noted that the various details described in this description should not be taken to imply that these details relate to elements that are essential components of the various embodiments described in this description, even in cases where a particular element is illustrated in each of the drawings that accompany the present description. Rather, the claims infra should be taken as the sole representation of the breadth of the present description and the corresponding scope of the various embodiments described in this description. Further, it should be apparent to those skilled in the art that various modifications and variations can be made to the described embodiments without departing from the spirit and scope of the claimed subject matter. Thus it is intended that the specification cover the modifications and variations of the various described embodiments provided such modification and variations come within the scope of the claims recited infra and their equivalents.

It should be understood that any two quantitative values assigned to a property may constitute a range of that property, and all combinations of ranges formed from all stated quantitative values of a given property are contemplated in this description. It should be appreciated that compositional ranges of a chemical constituent in a composition or formulation should be appreciated as containing, in some embodiments, a mixture of isomers of that constituent. It should be appreciated that the examples supply compositional ranges for various compositions, and that the total amount of isomers of a particular chemical composition can constitute a range.

As used in the Specification and appended Claims, the singular forms “a”, “an”, and “the” include plural references unless the context clearly indicates otherwise. The verb “comprises” and its conjugated forms should be interpreted as referring to elements, components or steps in a non-exclusive manner. The referenced elements, components or steps may be present, utilized or combined with other elements, components or steps not expressly referenced.

Where a range of values is provided in the Specification or in the appended Claims, it is understood that the interval encompasses each intervening value between the upper limit and the lesser limit as well as the upper limit and the lesser limit. The invention encompasses and bounds smaller ranges of the interval subject to any specific exclusion provided. As used herein, the word “about” followed by a number includes the stated number plus or minus two significant digits. 

What is claimed is:
 1. A wellbore cementing system comprising: a tubular positioned in a wellbore such that an annulus is formed between a geological formation and the tubular; and a cement structure positioned in at least a portion of the annulus, where the cement structure comprises from 1% to 40% BWOC of a swelling additive, and where the swelling additive comprises at least one micronized rubber in an amount from 50.0% to 95.0% BWOC, at least one distillate, and at least one solvent-refined heavy paraffinic.
 2. The wellbore cementing system of claim 1, where the at least one micronized rubber comprises nitrile rubber, styrene butadiene, fluoro silicone, isobutylene maleic anhydride, acrylic acid-type polymers, polyethylene oxide polymers, bentonite, and mixtures of these components.
 3. The wellbore cementing system of claim 1, where the at least one micronized rubber has a density from 10.0 lb/gal to 20.5 lb/gal.
 4. The wellbore cementing system of claim 1, where the at least one micronized rubber has a specific gravity from 0.85 to 1.10.
 5. The wellbore cementing system of claim 1, where the at least one micronized rubber comprises a mixture of carbon black, zinc oxide, and an elastomer.
 6. The wellbore cementing system of claim 5, where the carbon black comprises from 10.0% to 40.0% BWOC of the at least one micronized rubber, the zinc oxide comprises less than 3.0% BWOC of the at least one micronized rubber, and the elastomer comprises from 60.0% to 80.0% BWOC of the at least one micronized rubber.
 7. The wellbore cementing system of claim 1, where the at least one micronized rubber comprises a mixture of acrylonitrile rubber, zinc oxide, and styrene butadiene copolymer.
 8. The wellbore cementing system of claim 7, where the acrylonitrile rubber comprises from 25.0% to 50.0% BWOC of the at least one micronized rubber, the zinc oxide comprises less than 2.5% BWOC of the micronized rubber, and the styrene butadiene copolymer comprises from 50.0% to 70.0% BWOC of the micronized rubber.
 9. The wellbore cementing system of claim 1, where the swelling additive has a density from 0.5 g/cm³ to 2.0 g/cm³.
 10. The wellbore cementing system of claim 1, where the cement structure has a Young's modulus 10 days after curing from 7.50×10⁵ psi to 7.95×10⁵ psi.
 11. The wellbore cementing system of claim 1, where the cement structure has a Young's modulus 20 days after curing from 5.50×10⁵ psi to 6.00×10⁵ psi.
 12. The wellbore cementing system of claim 1, where the cement structure has a Young's modulus 30 days after curing from 7.00×10⁵ psi to 7.50×10⁵ psi.
 13. The wellbore cementing system of claim 1, where the cement structure has a Poisson's ratio 10 days after curing from 0.370 psi to 0.400 psi.
 14. The wellbore cementing system of claim 1, where the cement structure has a Poisson's ratio 20 days after curing from 0.330 psi to 0.360 psi.
 15. The wellbore cementing system of claim 1, where the cement structure has a Poisson's ratio 30 days after curing from 0.705 psi to 0.735 psi.
 16. The wellbore cementing system of claim 1, where the cement structure has a density from 100 pcf to 170 pcf. 